Annular blowout preventers are well known to those familiar with oil or gas well drilling and completion operations. Blowout preventers are ordinarily disposed at the top of a well, just below the drilling floor, and are designed to seal off the hole in the event of a sudden increase in downhole pressure. Such an increase might occur, for example, when the drill bit breaks through a subterranean formation into a pocket of pressurized gas.
Blowout preventers are aligned with the well bore and typically comprise a housing containing one or more annular packer elements, along with a series of ram-type packers, maintained within a recess in the drilling floor. The packer elements of annular blowout preventers typically comprise a relatively massive annulus of rubber having relatively flat upper and lower surfaces, a beveled outer surface, and a centrally disposed, generally cylindrical opening. The rubber is typically molded around a plurality of circumferentially spaced-apart metal inserts comprising top and bottom transverse flange portions having vertically extending web portions disposed therebetween. The transverse flange portions are typically characterized by relatively major radial and circumferential dimensions and a relatively minor axial dimension, whereas the vertically extending web portions typically comprise relatively major radial and axial dimensions, and a relatively minor circumferential dimension. During normal drilling conditions, the packer element remains in a standby position with the drill string passing through its central opening. When in this position, sufficient space remains between the drill stem and the interior surface of the blowout preventer to permit circulation of drilling mud and the like. However, when pressure sensors disposed inside the well detect a sudden increase in downhole pressure, the packer element is adapted to be compressed inwardly around the drill stem, thereby sealing off the annular space in the well bore. Annular blowout preventers are preferably designed in such manner that if no drill stem is present in the central opening, the packer element will still compress sufficiently to seal off the hole. This is referred to as a blind closure. When the packer element is compressed, the metal inserts are squeezed into closer circumferential relation to each other, thereby squeezing the rubber that is disposed between adjacent inserts into the central opening.
Once the downhole pressure has been alleviated in a controlled manner, the hydraulic compressive force on the packer element is released, and it will desirably return to its previous configuration. For conventional Type GK blowout preventers, the normal useful life ranges up to about 30 cycles of operation. A blowout preventer is considered to have failed when it is no longer able to seal off a well bore when subjected to its rated pressure. Failure usually results when the metal inserts become delaminated from the surrounding rubber material, although other factors such as tearing, abrasion, and attack by oils or chemicals present in the drilling mud can also contribute to failure.
In the past, natural rubber, neoprene, and some other elastomers were utilized in making packer elements for blowout preventers. The use of such materials is disclosed, for example, in U.S. Pat. No. 2,609,836. More recently, nitrile rubbers, and more particularly, acrylonitrile-butadiene copolymers, have been recognized as providing a better overall balance of physical and chemical properties for use in this application. However, the costs associated with replacing packer elements in blowout preventers are significant, and there remains a great need for parts which demonstrate improved durability and longevity without an associated increase in part cost.